Methods for shut-in pressure escalation analysis

ABSTRACT

Methods for using shut-in pressures to determine uncertainties in a hydraulic fracturing process in a shale reservoir are described. Data commonly collected during multistage fracturing is used to calculate propped fracture height and induced stresses, as well as other variables, in the presence of horizontal stress anisotropy. These variables can then be incorporated into reservoir simulations to improve the fracturing monitoring, forecast hydrocarbon recoveries, or modify fracturing plans.

PRIOR RELATED APPLICATIONS

This application is a continuation of U.S. Ser. No. 16/986,779(allowed), filed on Aug. 6, 2020, which is a continuation of U.S. Ser.No. 15/823,762 (U.S. Pat. No. 10,753,181), filed on Nov. 28, 2017, whichclaims priority to U.S. Ser. No. 62/427,262 (expired), filed Nov. 29,2016. Each are expressly incorporated by reference herein in theirentirety for all purposes.

FEDERALLY SPONSORED RESEARCH STATEMENT

Not applicable.

REFERENCE TO MICROFICHE APPENDIX

Not applicable.

FIELD OF THE DISCLOSURE

The disclosure generally relates to improvements to hydraulic fracturingtreatment of oil-containing reservoirs. Specifically, methods ofevaluating hydraulic fractures using shut-in pressures are disclosed.

BACKGROUND OF THE DISCLOSURE

Unconventional hydrocarbon reservoirs are any reservoir that requiresspecial recovery operations outside the conventional operatingpractices. Unconventional reservoirs include reservoirs such astight-gas sands, gas and oil shales, coalbed methane, heavy oil and tarsands, and gas-hydrate deposits. These reservoirs have little to noporosity, thus the hydrocarbons may be trapped within fractures and porespaces of the formation. Additionally, the hydrocarbons may be adsorbedonto organic material of an e.g. shale formation.

The rapid development of extracting hydrocarbons from theseunconventional reservoirs can be tied to the combination of horizontaldrilling and induced fracturing (called “hydraulic fracturing” or simply“fracking” or “frac'ing”) of the formations. Horizontal drilling hasallowed for drilling along and within hydrocarbon reservoirs of aformation to better capture the hydrocarbons trapped within thereservoirs. Additionally, increasing the number of fractures in theformation and/or increasing the size of existing fractures throughfracking may increase hydrocarbon recovery.

In a typical hydraulic fracturing treatment, fracturing treatment fluidcontaining a proppant material is pumped downhole into the formation ata pressure sufficiently high enough to cause fracturing of the formationor enlargement of existing fractures in the reservoir. Proppant materialremains in the fracture after the treatment is completed, where itserves to hold the fracture open, thereby enhancing the ability offluids to migrate from the formation to the well bore through thefracture. The spacing between fractures as well as the ability tostimulate the fractures naturally present in the rock may be majorfactors in the success of horizontal completions in unconventionalhydrocarbon reservoirs.

While there are a great many fracking techniques, one useful one is“plug-and-perf” fracking. Plug-and-perf completions are extremelyflexible multistage well completion techniques for cased hole wells.Each stage can be perforated and treated optimally because options canbe exercised up to the moment the perforating gun is fired. The engineercan apply knowledge from each previous stage to optimize treatment ofthe current stage.

The process consists of pumping a plug-and-perforating gun to a givendepth. The plug is set, the zone perforated, and the tools removed fromthe well. A ball is pumped downhole to isolate the zones below the plugand the fracture stimulation treatment is pumped in. The ball-activatedplug diverts fracture fluids through the perforations into theformation. After the stage is completed, the next plug and set ofperforations are initiated, and the process is repeated moving furtheralong the well.

Improvements in hydrocarbon recovery with fracking depend on fracturetrajectories, net pressures, and spacing. Thus, the ability to monitorthe geometry of the induced fractures to obtain optimal placement andstimulation is paramount. An induced fracture may be divided into threedifferent regions (hydraulic, propped, and effective), but out of thethree fracture dimensions, only the last one is relevant to a reservoirmodel, and may be used to forecast future production.

One common way of evaluating the geometry of hydraulic fractures duringwell stimulation is through microseismic measurements. However, thismethod has a few disadvantages. First, it is an indirect method, asmicroseismicity captures the shear failure of well stimulation, but nottensile opening of the hydraulic fracture itself. In addition, thephysical meaning of microseismic events and how they relate to thehydraulic fracture is still widely debated in the literature. Further,the method is subject to a significant uncertainty in the location ofthe microseismic events.

Another common method used in industry is pressure-transient analysis or“PTA”. But, this method often leads to a wide range of potentialfracture geometries.

PTA, Rate Transient Analysis or “RTA” and numerical modeling are widelyused techniques to characterize effective fracture dimensions andfracture conductivity. Unfortunately, as these methods analyze thecombined contribution of all induced fractures and rely on simplisticassumptions of the induced fracture system, they often lead tonon-unique solutions and require additional data to further constrainthe range of potential outcomes.

All of current methods used to estimate fracture dimensions andhorizontal stresses can only be applied on a limited number of wellsbecause of the significant incremental cost (procedure and additionalequipment) or the time/effort required to complete the assessment.

Thus, what is needed in the art are improved methods of evaluating thehydraulic fracturing for every well being hydraulically stimulated.Although hydraulic fracturing is quite successful, even incrementalimprovements in technology can mean the difference between costeffective production and reserves that are uneconomical to produce.

SUMMARY OF THE DISCLOSURE

Disclosed herein are methods for evaluating the hydraulic fracturing forevery well being hydraulically stimulated, optimize the fracturingprogram based on the evaluations, and implementing the modifications atthe wellsite. Specifically, the methods estimate some of the mostimportant uncertainties associated with hydraulic fracturing in eachstage, especially in shale reservoirs: 1) hydraulic-fracture height,length and induced fracture area; and, 2) in-situ horizontal-stressanisotropy (σ_(hmax)-σ_(hmin)) and adjust the fracturing programaccordingly on subsequent stages and/or similar wellsites.

Knowledge of the horizontal-stress anisotropy is critical for manyaspects of the design of multistage completions and field development. Alow value of the horizontal-stress anisotropy may be a limiting factorin the ability to space down perforation clusters, as fracturereorientation may take place. The impact may also be felt when trying tostimulate infill wells following production of one or several parentwells. Depletion will impact not only stress magnitude, but may alsoreorient stresses in the field, such that the propagation direction offractures initiated from an infill well may differ from the preferabletransverse direction. Operationally, it may impact the spacing ofperforations clusters, the sequencing of multi-well fracturingoperations, as well as the timing and design of infill and refracturingoperations. The present methods can be used to determine if fracturingreorientation is likely to be occurring.

If fracturing reorientation is not occurring, then the fracture height,length, and surface area can be estimated using the disclosed methods.

As stress induced by the completion is strongly influenced by stage andperforation cluster spacing, the method can be used in conjunction withother diagnostic methods to help guide completion optimization,especially in the early appraisal phase.

In its most basic form, the evaluation steps in the method, referred toherein as the Instantaneous Shut-in Pressure (ISIP) Analysis, comparesthe shut-in pressure escalation for each fracturing stage with atwo-parameter exponential recovery equation, the type-curves of theload-normalized stress plateau, escalation, and interference ratio, aswell as the fracture-reorientation criterion, to estimatehydraulic-fracture height and horizontal-stress anisotropy.

The key parameters—hydraulic-fracture height and horizontal-stressanisotropy—can then be used to optimize completion designs in horizontalwells, including stage and perforation cluster spacing, fluidtype/volume and the like, reservoir development, and/or forecasting. Theuser is only required to input the collected shut-in pressures and thefollowing parameters cluster spacing, number of perforationclusters/stage, well depth and fracture closure gradient.

For certain fracturing operations, additional information such asfracture length is needed. As such, other embodiments of the methodutilizes additional fracturing information such as the Young's modulus,Poisson's ratio, and slurry volume pumped for each stage to calculate toevaluate parameters such as the hydraulic-fracture length and inducedfracture area.

The methods described herein take into account the connection betweenfracking design and in-situ stresses to determine the resulting inducedfractures and stresses (geomechanical stress interference). Further, themethods aid in developing and executing a fracturing plan with maximalefficiencies, and thereby improve hydrocarbon recoveries.

Because every fracturing stage will contribute to a reduction in theformation's horizontal stress anisotropy, the ISIP analysis is a usefultool to guide the spacing design of perforation clusters. As a result,an ISIP analysis is a useful addition to any workflow looking tooptimize well spacing and stacking in unconventional plays.

The calculations in the described methods are preferably programmed intoa spreadsheet or solver software. The embodiments described here utilizeMicrosoft Excel due to its ease of use and industry-wide acceptance.Excel has multiple solver add-ins and can quickly perform thecalculations with little user input. Thus, the methods can be used withminimal training or user input. Other exemplary software includesNumbers from Apple, Apache OpenOffice, LibreOffice and Google Sheets, aswell as numerical computing environments such as MATLAB or Python.

Any method described herein can further include the step of using theresults in a reservoir simulation program to predict reservoirperformance characteristics, such as fracturing, production rates, totalproduction levels, rock failures, faults, wellbore failure, optimalstage and perforation cluster spacing, and the like.

Any method described herein can also include the step of using theresults to optimize and implement a hydraulic fracturing program ormodify a hydraulic fracturing program or pattern for subsequent steps ina given well or wellpad. The final frack plan is thus implemented, andthe well is fractured according to the final plan. The inventive methodsmay also include the subsequent production of hydrocarbons from thefracked well. Further, the optimized fracturing program can also be usedon similar wells.

The results from the ISIP Analysis steps can be inputted into any knownreservoir simulation software that is commercially available ordeveloped in-house. Exemplary software include IMEX, GEM or Stars (CMG);VIP and Nexus (Halliburton); Mangrove, Eclipse and Intersect(Schlumberger); and FRACGEN/NFFLOW (National Energy TechnologyLaboratory). For shale reservoirs, FRACMAN™ and MSHALE™ may bepreferred. These models can be used with appropriate plugins ormodifications needed to practice the claimed methods.

One advantage of the method is that it is a fracture/stress diagnosticmethod that uses data that is systematically available for every wellbeing hydraulically stimulated. This “free data” not only saves time andcosts, but allows the method to be quickly implemented on site by afield completion engineer. Also, the method does not require additionalfield operations or downhole/surface equipment, thus savingimplementation costs.

The “free data” is typically obtained following the end of injection ofeach fracturing stage of a plug-and-perf hydraulic stimulation, afterfriction forces in the wellbore, perforations and near-wellbore regiondissipate. While ISIPs may be obtained during Diagnostic FractureInjection Test (DFIT), the method described herein generally applies toISIPs measured at the end of fracturing stages in a plug & perfcompletion.

The typical evolution of bottom hole pressure recorded at the end of afracturing stage is shown in FIG. 1.

The ISIP is measured at the end of a Diagnostic Fracture Injection Test(DFIT), which has become the primary transient test for the ultra lowpermeability shales developed in the United States. The DFIT consists ofinjecting a relatively small volume of fluid at a low rate throughperforations in a cemented casing to create a small-scale hydraulicfracture. The fracture propagates out past any drilling damage andallows the pressure signal during the fall off to be in contact with thereservoir matrix. DFITs may be run at different depths of a verticalwellbore to obtain multiple stress calibration points, or at the toe ofa horizontal well, prior to stimulation operations. Along with closurepressure, which is equal to the minimum horizontal stress, DFITs may beused to estimate leak-off rate, reservoir pressure and permeability.

The current methods utilize the instantaneous shut-in pressure databecause analysis of non-instantaneous shut-in pressure data (i.e. 3-min,5-min shut-in pressures) will result in erroneous evaluations of thetotal stress induced by the completion and the hydraulic fractureheight.

In more detail, the ISIP analysis consists of four basic steps:

1. Collect shut-in pressure data.

2. Match shut-in pressure data with a modified linear time invariantsystem.

3. Determine causes of stress plateaus.

4. Calculate fracture height, horizontal-stress anisotropy, and othervariables using type-curves, based on Eq. 1, shown below, if no fracturereorientation is expected.

The ISIP is recorded at the end of each fracturing stage during DFIT andis matched with a two-parameter exponential recovery equation (EQU. 1):

$\begin{matrix}{{\Delta\;{\sigma_{shadow}(n)}} = {\Delta\;{\sigma_{plateau}\left( {1 - e^{\frac{1 - n}{Escalation}}} \right)}}} & {{Equ}.\mspace{11mu} 1}\end{matrix}$

In EQU. 1, n is the stage number, Δσ_(plateau) represents the totalvalue of stress interference that is produced by the stimulation andΔσ_(shadow) is the stress interference contribution that increases witheach new fracturing stage.

This equation is a typical first-order, linear time invariant system;however, the time constant has been replaced with the escalation numberbecause it is the key parameter for characterizing the dynamic responseof the fracturing. The escalation number represents how “quickly” stressinterference approaches the plateau. More specifically, it representsthe number of fracturing stages necessary for induced stresses to reachsome arbitrary percentage of the stress plateau.

The induced stresses will never reach 100% of the stress plateau due tothe natural logarithm in the equation. Hence, in order to quantify howfast ISIPs converge toward the plateau, a smaller percentage target mustbe chosen. The value that simplifies the formulation of thestress-escalation equation (EQU. 1) is 1-1/e, or 63.2%. This value iscommonly used with linear time invariant systems in other applicationsof the exponential recovery equation in physics and engineering. Thenumber of stages required to reach 63.2% of the stress plateau is calledthe Escalation number (EQU. 1).

In matching Equation 1 and the ISIP data, the most straightforwardsolution consists in minimizing the squared differences between the dataand match (least-squares method). In Excel, and other spreadsheetprograms, optimization solvers or add-ins can be used to processmultiple iterations where the two parameters, stress plateau andescalation, are changed to obtain the smallest squared difference. Theadvantage of using the method with Excel is that a match quality is alsoobtained during the least-squares analysis. The match quality can beanother factor in evaluating the data's match with Equation 1.

Once the stress plateau and escalation parameters are determined, thestress plateau can be compared with the stress load to determine thecause of the plateau. FIG. 3 displays the workflow for evaluating thestress plateau.

If the plateau is naturally occurring, the stress load will have a valuethat is much smaller than the net pressure at shut-in. On the otherhand, when maximum horizontal stress is overcome, and stress escalationis basically cut short, this will cause the stress load to takeabnormally high values.

For example, the stress load may not be higher than the net pressure atshut-in. When it happens, this is a clear indication that horizontalstress-anisotropy is responsible for the stress plateau.

Generally, if the stress load is less than half the net-pressure atshut-in, this should give some confidence that fracture reorientation islimited, and that the fracture height calculation may be trusted.However, if the stress load is high, then the ISIP analysis should endbecause the remaining parameter calculations are questionable.

To reach the evaluation stage of the stress plateau and stress load,type-curves may be used to estimate the interference ratio, totalfracture height and stress load. Type-curves may be generated using theanalytical formulation for a penny-shaped fracture, or any expression ofthe stress-correction factor Φ that may be derived either analyticallyor obtained through numerical modeling (in geomechanical codes such asABAQUS, FLAC3D, VISAGE). Such fracture expressions are known in the artand new expressions may be developed.

Simple analytical equations of the decay in stress interference awayfrom a dilated crack exist for two specific fracture geometries (Sneddon1946, Sneddon et al 1946): 1. Semi-infinite fracture (L_(f)>>h_(f)) and2. Penny-shaped fracture (L_(f)=h_(f)). The increase in stress away froma dilated crack (Δσ_(xx)) can be normalized by the net shut-in pressureinside the fracture (p_(net)), and is maximum at the surface of thefracture. Such normalized forms are referred to as the stress-correctionfactor Φ (i.e. Φ=Δσ_(xx)/p_(net)). The stress-correction factor isalways between 0 and 1, and represents the decay of stress interferenceaway from a single fracture. The analytical expressions of the stresscorrection factor on a line perpendicular to a dilated fracture andgoing through its center are provided in EQU. 2 and EQU. 3, respectivelyfor a semi-infinite and a penny-shaped fracture, and are plotted in FIG.2.

$\begin{matrix}{\Phi_{{semi}\text{-}{infinite}} = {1 - {\left( \frac{s_{f}}{h_{f}} \right)^{3}\left\lbrack {1 + \left( \frac{s_{f}}{h_{f}} \right)^{2}} \right\rbrack}^{{- 3}/2}}} & {{EQU}.\mspace{11mu} 2} \\{\Phi_{{penny}\text{-}{shaped}} = {\frac{2}{\pi}\left\lbrack {{\frac{s_{f}}{h_{f}}\frac{\left( {s_{f}^{2} - h_{f}^{2}} \right)^{2}}{\left( {s_{f}^{2} + h_{f}^{2}} \right)^{2}}} - {\tan^{- 1}\left( \frac{h_{f}}{s_{f}} \right)}} \right\rbrack}} & {{EQU}.\mspace{11mu} 3}\end{matrix}$

The multi-stage analytical model of stress interference is then built bysuperposing the stress interference for multiple consecutive fractures,based on the proposed recurrence relationship in EQU. 4:

$\begin{matrix}\begin{matrix}{{\Delta\;{\sigma_{shadow}\left( {n + 1} \right)}} = {\Phi\left\lbrack {\sigma_{load} + {\Delta\;{\sigma_{shadow}(n)}}} \right\rbrack}} \\{= {{{\Phi\Delta}\;{\sigma_{shadow}(n)}} + {\Phi\sigma}_{load}}}\end{matrix} & {{EQU}.\mspace{11mu} 4}\end{matrix}$

Wherein Δσ_(shadow)(0)=0 and Δσ_(shadow)(1)=Φσ_(load). EQU. 4 may alsobe solved analytically, by elevating the order of the recurrenceequation, in order to render it homogeneous. The solution of therecurrence equation is a two-parameter equation and is function of thestress-correction factor Φ and of the stress load (σ_(load)) (EQU. 5).

$\begin{matrix}{{\Delta\;{\sigma_{shadow}(n)}} = {\frac{{\Phi\sigma}_{load}}{1 - \Phi}\left( {1 - \Phi^{n - 1}} \right)}} & {{EQU}.\mspace{11mu} 5}\end{matrix}$

The parameters of the empirical form of the stress-escalation equation(EQU. 1) can be expressed as a function of the parameters of theanalytical form of the stress-escalation equation (EQU. 5) as shown inEQU. 6, EQU. 7 and EQU. 8

$\begin{matrix}{{\Delta\;\sigma_{plateau}} = {{\lim\limits_{n\rightarrow\infty}{\Delta\;{\sigma_{shadow}(n)}}} = {{\lim\limits_{n\rightarrow\infty}\left( {\frac{{\Phi\sigma}_{load}}{1 - \Phi}\left( {1 - \Phi^{n - 1}} \right)} \right)} = \frac{{\Phi\sigma}_{load}}{1 - \Phi}}}} & {{EQU}.\mspace{11mu} 6} \\{{{Interference}\mspace{14mu}{Ratio}} = {{\frac{d}{dn}\left( \frac{\Delta\;{\sigma_{shadow}(n)}}{\sigma_{load}} \right)_{n = 1}} = {{{- \frac{\Phi}{1 - \Phi}}\left( \frac{d\;\Phi^{n - 1}}{dn} \right)_{n = 1}} = \frac{\Phi\;{\ln(\Phi)}}{\Phi - 1}}}} & {{EQU}.\mspace{11mu} 7} \\{{Escalation} = {\frac{\Delta\;\sigma_{plateau}}{\sigma_{load} \times {Interference}\mspace{14mu}{Ratio}} = \frac{- 1}{\ln(\Phi)}}} & {{EQU}.\mspace{11mu} 8}\end{matrix}$

Type-curves prepared exclusively for the described methods can be usedfor the determination of the hydraulic fracture height for a givenmulti-stage simulation. The type-curves were developed by matchinganalytical models of multi-stage mechanical stress interference with thestress equation (EQU. 1). However, these type-curves assume asemi-infinite fracture geometry (L_(f)>>h_(f)).

The prepared type-curves, shown in FIGS. 4A-E, were created for 1-5perforation clusters per stage for load-normalized stress plateaus,escalation number, and interference ratio, assuming the hydraulicfractures are semi-infinite (L_(f)>>h_(f)). Other sets of type-curvesmay be developed with different assumptions on the fracture geometry,hence for different expressions of the stress-correction factor Φ. Eachplot was also matched with a power-law equation (FIG. 4A-D) orpolynomial equations (FIG. 4E).

A user can manually go through each prepared type-curve to determine thestress load or interference ratio. Or, if using a spreadsheet, thepower-law equations or polynomial equations can be coded into thespreadsheet and the calculation of the fracture height can be automated.

The outputs of the ISIP model include the horizontal-stress anisotropy(σ_(hmax)-σ_(hmin)) which can be used in a geomechanical model (such asABAQUS, FLAC3D, VISAGE, etc.), and hydraulic fracture height and length(including surface area), which can be used as inputs in reservoir andgeomechanical models, and help calibrate fracturing models (like GOHFER,STIMPLAN, MANGROVE, etc.). The methods describe above utilizenon-transitory machine-readable storage medium, which when executed byat least one processor of a computer, performs the steps of themethod(s) described herein.

Once the ISIP analysis is complete, the fracturing models can beoptimized according to the results of the ISIP analysis and can then beimplemented in future fracturing stages or at similar wells. Onceimplemented, hydrocarbon production can commence or continue.

Hardware for implementing the inventive methods may preferably includemassively parallel and distributed Linux clusters, which utilize bothCPU and GPU architectures. Alternatively, the hardware may use a LINUXOS, XML universal interface run with supercomputing facilities providedby Linux Networx, including the next-generation Clusterworx Advancedcluster management system. Another system is the Microsoft Windows 7Enterprise or Ultimate Edition (64-bit, SP1) with Dual quad-core orhex-core processor, 64 GB RAM memory with Fast rotational speed harddisk (10,000-15,000 rpm) or solid state drive (300 GB) with NVIDIAQuadro K5000 graphics card and multiple high resolution monitors.Alternatively, many-cores can be used in the computing. Slower systemscould also be used, because the processing is less compute intensivethan for example, 3D seismic processing.

Ideally, the inventive methods are performed in the same computersrunning the modeling programs to ease the transfer of data after theISIP analysis steps. However, this is not a requirement.

This summary is provided to introduce a selection of concepts that arefurther described below in the detailed description. This summary is notintended to identify key or essential features of the claimed subjectmatter, nor is it intended to be used as an aid in limiting the scope ofthe claimed subject matter. Further, there are many ways to writeequations, and /or write similar equations that produce similar results,so all equations discussed herein are intended to include equivalentsthereof.

“Fracing” or “Fracking”, as used herein, may refer to any process usedto manually initiate and propagate a fracture in a rock formation, butexcludes natural fracking. Additionally fracking may be used to increaseexisting fractures in a rock formation. Fracking may include forcing ahydraulic fluid in a fracture of a rock formation to increase the sizeof the fracture and introducing proppant (e.g., sand) in the newlyinduced fracture to keep the fracture open. The fracture may be anexisting fracture in the formation, or may be initiated using a varietyof techniques known in the art. “Hydraulic Fracking” means that pressurewas applied via a fluid.

As used herein, “anisotropic stress” means stress values are differentin different directions.

“Horizontal stress anisotropy” is the difference between minimum andmaximum horizontal stress (σ_(hmax)-σ_(hmin)). It impacts how inducedfractures interact with planes of weakness naturally present in theformation. Elevated values of the horizontal stress anisotropy canindicate tensile branching of induced fractures along natural fracturesbeing impeded, thus preventing fracture complexity and ultimatelydecreasing the surface area contacted by the hydraulic stimulation.

“Fracture reorientation” involves inducing a second artificial fractureinto a altered-stress zone, with this secondary fracture propagating ina different direction from the original. For reorientation to occur, thefar-field stress regime has to have altered in orientation from the timethe original fracture was created.

“Shut-in pressure” (SIP) refers to the surface force per unit areaexerted at the top of a wellbore when it is closed at either theChristmas tree or the BOP stack. The pressure may be from the formationor an external and intentional source, and combinations thereof. The SIPmay be zero, indicating that any open formations are effectivelybalanced by the hydrostatic column of fluid in the well. If the pressureis zero, the well is considered to be dead, and can normally be openedsafely to the atmosphere.

As used herein, “instantaneous shut-in pressure” or “ISIP” is the finalinjection pressure excluding pressure drop due to friction in thewellbore and perforations or slotted liner. There are numerous ways toestimate ISIP, any of which can be used hereunder, but the preferredmethod records the pressure value past the early rapid falloff. Waterhammer often occurs following shut-in, and common practice is toextrapolate the slope at the end of the water hammer to the shut-intime.

ISIPs escalate from toe to heel in all wells as a result of themechanical interference induced by hydraulic fractures often referred toas “stress shadowing”. However, the ISIP typically reaches a “stressplateau” after the first couple of stages.

“ISIP Analysis” is the evaluation steps of the methods disclosed hereinthat matches the ISIP escalation during a multi-stage plug-and-perfcompletion with developed analytical equations and type-curves to obtainfracturing information such as fracture height, length, and area and thehorizontal stress anisotropy. The results of the ISIP analysis areutilized by modeling programs for optimizing a reservoir simulationplan, although other uses in the reservoir and geomechanical models arepossible.

A “water hammer” is used in accordance with its art accepted meaning ofa pressure transient. A pressure transient is generated when a suddenchange in injection rate occurs due to a valve closure or injectorshutdown. This pressure transient—referred to as a water hammer—travelsdown the wellbore, is reflected back and induces a series of pressurepulses on the sand face.

As used herein, “escalation number” refers to number of stages afterwhich induced stresses are equal to some pre-determined percentage ofthe stress plateau. It is independent of the stress load.

By “in-situ closure stress”, the in-situ minimum horizontal stress ashydraulic fractures propagate perpendicular to the minimum horizontalstress direction. When the pressure in the fracture is greater than thefracture-closure pressure, the fracture is open.

By “stress load”, we refer to the net pressure in the hydraulicfracture(s) of one stage just prior to the start of the subsequentstage, which is the source of induced stress interference. Factorsinfluencing the magnitude of the stress load include:

-   -   Volume of the slurry pumped during the stage    -   Fracture geometry (height, length, number of perforation        clusters)    -   Mechanical properties (Young's modulus, Poisson's ratio)    -   Resting time between consecutive stages    -   Leak-off coefficient

Residual load exists as the fracture fluids leaks off and the fracturefaces close on the proppant, which is a function of the “closure load”(i.e. amount of proppant/stage).

“Stress interference” refers to stresses that interfere in the fracturepropagation and result in reorientation. Stress interference phenomenahave tremendous diagnostic value as they relate to the: 1) geometry ofthe induced fractures (height) and 2) in-situ stresses. The stressinterference increases which each new fracturing stage.

The “interference ratio” is defined as:

${{Interference}\mspace{14mu}{Ratio}} = \frac{\Delta\;\sigma_{plateau}}{\sigma_{load} \times {Escalation}}$

and represents the relative magnitude of stress interference betweensubsequent stages, which is always comprised between 0 and 1. Thetighter the stage spacing the larger the induced stress plateau is for agiven value of the escalation number.

“Type-curves” as used herein, refer to those graphs built by matchinganalytical models of multi-stage mechanical stress interference with thestress equation provided by Equation 1. The response of the type-curveshas also been captured by correlation equations for ease ofcalculations. The type-curves, and correlation equations, presented hereare for use with the disclosed ISIP analysis. No additional type-curvesneed to be prepared to use the analysis.

“Match curves” as used herein, refer to the best fit of thestress-escalation equation with collected shut-in pressures obtained bymeans of a regression method, preferably linear least squaresregression. The Δσ_(plateau) and escalation number are varied until asolution to Equation 1 that minimizes the sum of the squared deviationsbetween the data and the model is found.

The use of the word “a” or “an” when used in conjunction with the term“comprising” in the claims or the specification means one or more thanone, unless the context dictates otherwise.

The term “about” means the stated value plus or minus the margin oferror of measurement or plus or minus 10% if no method of measurement isindicated.

The use of the term “or” in the claims is used to mean “and/or” unlessexplicitly indicated to refer to alternatives only or if thealternatives are mutually exclusive.

The terms “comprise”, “have”, “include” and “contain” (and theirvariants) are open-ended linking verbs and allow the addition of otherelements when used in a claim.

The phrase “consisting of” is closed, and excludes all additionalelements.

The phrase “consisting essentially of” excludes additional materialelements, but allows the inclusions of non-material elements that do notsubstantially change the nature of the invention.

The following abbreviations are used herein:

ABBREVIATION TERM Δσ_(h) Horizontal stress anisotropy (σ_(hmax) −σ_(hmin)) Δσ_(shadow(n)) Stress interference at n stage E Young'smodulus Escalation Escalation number FT feet h_(f) Fracture half-heightInterference Interference Ratio ISIP Instantaneous shut-in pressureL_(f) Fracture half-length n_(cluster) Number of perforation clustersper stage perf Perforation p_(f) Fracturing pressure at shut-in p_(net)Net pressure in the hydraulic fractures at shut-in (=p_(f) − σ_(hmin))PSI Pound per square inch PTA Pressure Transient Analysis RTA RateTransient Analysis s_(cluster) Spacing between perforation clusterss_(f) Spacing between fracturing stages V_(slurry) Slurry volume perstage Δσ_(plateau) Induced stress plateau ν Poisson ratio σ_(hmax)Horizontal maximum stress σ_(hmin) Horizontal minimum stress σ_(hmin)_(—) _(insitu) In-situ closure stress σ_(load) Stress load σ_(v)Overburden stress γ Stress-correction factor

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1. Typical downhole pressure record during a fracturing stage (Yewand Weng 2015).

FIG. 2. Analytical expressions of the stress correction factor on a lineperpendicular to a dilated fracture and going through its center.

FIG. 3 Workflow to determine cause of stress plateau.

FIG. 4A-E. Type-curves for fracturing procedures having 1-5 perforationclusters per stage.

FIG. 5A displays an exemplary plot of ISIP data collected from the 6Hwell in the Shale I formation along with the type-curve for the matcheddata and the optimized stress plateau and escalation.

FIG. 5B displays a screenshot of the spreadsheet template for the 6Hwell.

FIG. 6 shows the ISIP evolution and match for the 8H (circle markers andsolid line), 9H (square markers and dashed line), and 1H (triangularmarkers and dotted line) wells in the Shale I formation.

FIG. 7 displays the instantaneous, 3-min, and 5-min shut-in pressuresfor the Shale II well 1H.

FIG. 8 shows the ISIP evolution and match for the instantaneous (circlemarkers and solid line), 3-min (triangular markers and dotted line), and5-min (square markers and dashed line) shut-in pressures for well 1H.

FIG. 9 provides an ISIP gradient for two Shale III formation wells.

FIG. 10 provides the optimization of perforation cluster and stagespacing for the Shale I formation.

DESCRIPTION OF EMBODIMENTS OF THE DISCLOSURE

The invention provides novel analytical methods to calculate hydraulicfracture dimensions and in-situ horizontal stress anisotropy from theescalation of instantaneous shut-in pressures in a multi-stagehorizontal completion. The shut-in pressure and a series of type-curvescan be used to estimate fracture variables that are typically hard todetermine. From there, an operator can determine if there is significantfracture overlap and inefficient recovery. The reservoir simulation plancan then be optimized to overcome any inefficiency.

The present methods includes any of the following embodiments in anycombination(s) of one or more thereof:

-   -   A method for fracturing a reservoir including obtaining shut-in        pressure in a reservoir for n stages of a multistage fracturing        process having a known cluster number per stage and stage        spacing and calculating a net pressure at shut-in; inputting the        shut-in pressure data into a spreadsheet software stored in a        non-transitory memory of a computer and matching the shut-in        pressure with Equation 1 or its equivalent by varying an        estimated stress plateau parameter and an estimated escalation        number using a regression method in the spreadsheet software;        extrapolating the stress interference (I) using the type-curves        in FIG. 4C-E (or their equivalent) for the cluster number per        stage, the estimated escalation number, and the estimated stress        plateau parameter, calculating the stress load using Equation 9        or its equivalent; determining if stress plateau is caused by        overcoming the in-situ horizontal stress anisotropy by comparing        the calculated stress load with the net pressure at shut-in,        wherein the stress plateau is considered to be naturally        occurring if the stress plateau is less than or equal to half of        the net pressure at shut-in, wherein the stress plateau is        considered to be caused by overcoming horizontal stress        anisotropy if the stress plateau is more than net pressure at        shut-in, and wherein if the stress plateau is naturally        occurring, the fracture height is calculating using Equation 10        or its equivalent; inputting said horizontal-stress anisotropy        and the fracture height into a reservoir model software;        optimizing a reservoir fracturing plan using the reservoir model        software; and, implementing the optimized reservoir fracturing        plan to fracture the reservoir.    -   A method for fracturing a reservoir including obtaining shut-in        pressure in a reservoir for n stages of a multistage fracturing        process having a known cluster number per stage and stage        spacing and calculating a net pressure at shut-in; inputting the        shut-in pressure data into a spreadsheet software stored in a        non-transitory memory of a computer and matching the shut-in        pressure with

${\Delta\;{\sigma_{shadow}(n)}} = {\Delta\;{\sigma_{plateau}\left( {1 - e^{\frac{1 - n}{Escalation}}} \right)}}$

or its equivalent by varying an estimated stress plateau parameter andan estimated escalation number using a regression method in thespreadsheet software; extrapolating the stress interference (I) usingthe type-curves in FIG. 4C-E (or their equivalent) for the clusternumber per stage, the estimated escalation number, and the estimatedstress plateau parameter, calculating the stress load using:

$\sigma_{load} = \frac{\Delta\;\sigma_{plateau}}{{Interference}\mspace{14mu}{Ratio} \times {Escalation}}$

or its equivalent; determining if stress plateau is caused by overcomingthe in-situ horizontal stress anisotropy by comparing the calculatedstress load with the net pressure at shut-in, wherein the stress plateauis considered to be naturally occurring if the stress plateau is lessthan or equal to half of the net pressure at shut-in, wherein the stressplateau is considered to be caused by overcoming horizontal stressanisotropy if the stress plateau is more than net pressure at shut-in,and wherein if the stress plateau is naturally occurring, the fractureheight is calculating using

$L_{f} = \frac{3V_{slurry}E}{\begin{matrix}{8{\pi\left( {1 - v^{2}} \right)}{h_{f}^{2}\left( {{{ISIP}(1)} - \sigma_{hmin}} \right)}} \\\left\{ {1 + {\left( {n_{cluster} - 1} \right)\left\lbrack {1 + \left( \frac{h_{f}}{2s_{cluster}} \right)^{2}} \right\rbrack}^{{- 3}/2}} \right\}\end{matrix}}$

or its equivalent; inputting said horizontal-stress anisotropy and thefracture height into a reservoir model software; optimizing a reservoirfracturing plan using the reservoir model software; and, implementingthe optimized reservoir fracturing plan to fracture the reservoir.

-   -   The above method, wherein the regression method is least squares        regression analysis and the matched equation has the smallest        squared differences.    -   Any of the above methods, wherein the implementing step occurs        between any two sequential stages in said multistage fracturing        process.    -   Any of the above methods, wherein the shut-in pressure is        collected while implementing an initial reservoir model. The        shut-in pressure can be measured at the surface, downhole, or        both.    -   Any of the above methods can include the optional step of        fracturing a next stage of the reservoir or another well in the        reservoir using the calculated stress load, horizontal-stress        anisotropy and fracture height. One or more of the following        modified parameter(s) of the fracturing process can be selected        and modified during the next stage: cluster number per stage,        cluster spacing, stage spacing, fracturing pressure, fracturing        fluid type, fracturing fluid volume, fracturing fluid viscosity,        proppant type, proppant mass, proppant concentration, pumping        rate, pumping schedule or combinations thereof    -   Any of the above methods can include a step for estimating the        hydraulic fracture length and the induced fracture area using        Equation 11 or its equivalent.    -   Any of the above methods can include the additional step of        recovering hydrocarbons.    -   Any of the above methods, type-curves can be developed using any        combination of Equations 1-8 or their equivalent and used in        place of the type curves in FIG. 4C-E.

A hydraulic fracture is a pressure-induced fracture caused by injectingfluid into a target rock formation. ‘Fracking fluid’ is pumped into theformation at pressures that exceed the fracture pressure—the pressure atwhich rocks break. When fractures are created in a deep-rock formation,natural gas, petroleum, and brine will flow more freely leading toimproved hydrocarbon recovery.

At the surface, a sudden drop in pressure indicates fracture initiation,as the fracking fluid flows into the fractured formation. To break therock in the target interval, the fracture initiation pressure mustexceed the sum of the minimum principal stress plus the tensile strengthof the rock.

The fracking fluid is mainly water with some additives such as sand orother proppants suspended with the aid of thickening agents (i.e. gels).The volume of fracking fluid injected includes the additional volumecreated during fracturing and the fluid loss to the formation fromleakoff through the permeable wall of the fracture. However, the rate offluid loss at the growing fracture tip is extremely high. Therefore, itis not possible to initiate a fracture with proppant in the fracturingfluid because the high fluid loss would cause the proppant at thefracture tip to reach the consistency of a dry solid, causing bridgingand screenout conditions. Consequently, some volume of clean fluid—apad—must be pumped before any proppant is pumped.

Proppant is then pumped in following the pad. When the hydraulicpressure is removed from the well, small grains of hydraulic fracturingproppants (either sand or aluminum oxide) hold the fractures open.

To reduce the number of wells that have to be drilled while increasinghydrocarbon recovery, horizontal wells are fractured in stages. A “frackstage” is simply a portion of the usually horizontal section of the wellthat is being fracked. Horizontal wells commonly have 30-40 frackstages, and the average number of stages per horizontal well in the USis around 16 today.

The horizontal stress anisotropy is the difference between maximum andminimum horizontal stress. While it is generally unknown as a result ofa lack of available methods, it plays a key role in the ability tostimulate natural fractures and generate complexity. Operationally, itmay impact the spacing of perforations clusters, the sequencing ofmulti-well fracturing operations, as well as the timing and design ofinfill and refracturing operations. Fracture reorientation tendenciesand deviation from the transverse fracture direction, will increase asthe stage spacing or the horizontal stress anisotropy decreases. Asevery frack stage will contribute to reduce the formation's horizontalstress anisotropy, there is a need to also monitor the design ofperforation cluster to optimizing well spacing and stacking inunconventional plays.

The ISIP analysis in the presently disclosed methods calculates thehydraulic length of induced fractures, as well as the hydraulic areastimulated by each frack stage, using only data that is systematicallyreported after every plug and perforation multi-stage completion. Thus,there is no need to use additional hardware, measurement time or anymodification to the well and completion design. Further, the ISIPanalysis can also provide estimates of the horizontal stress anisotropyfor use in optimization.

The ISIP analysis consists of four basic steps:

1. Collect shut-in pressure data

2. Match shut-in pressure data with a modified linear time invariantsystem equation;

3. Determine causes of stress plateaus

4. Calculate fracture height, horizontal-stress anisotropy, and othervariables using type-curves.

The ISIP analysis will be described in detail below and will referenceexemplary results and figures created with data obtained from the well6H in the Shale I formation for exemplification purposes.

First, the ISIP analysis assumes uniform stage spacing, perforationcluster spacing, number of perforation clusters per stage, stimulationdesign (especially volume of fluid pumped per stage), lag time betweensuccessive stages, hydraulic height, and mechanical properties. As frackfluid leak-off is highly stress-dependent, the stress load in the latterstages of a perforation plan will be less than the stage load at earlierstages when using non-instantaneous shut-in pressures. Thus, analyses ofnon-instantaneous shut-in pressure data (i.e. 3-min, 5-min shut-inpressures) will result in erroneous evaluations of the total stressinduced by the completion and the hydraulic fracture height. For thesereasons, the ISIP analysis requires the instantaneous shut-in pressurefor a well.

The collected ISIP data is then “matched” with data generated by EQU. 1.The most straightforward solution consists in minimizing the squareddifferences between the data and ‘match’ data generated by EQU. 1(least-squares linear regression). This is achieved by multipleiterations by the optimization method changing the value of the twomatching parameters: the stress plateau and escalation. As the currentmethod programmed into an Excel spreadsheet, a solver add-in was used tocalculate the iterations. Three optimization solvers are availablethrough Excel. However, GRG Nonlinear is fastest, and does not requirebounds to be defined for the matching parameters. Based on repeated use,it generally converges to a unique solution, hence would be arecommended method.

However, other solver add-ins for other spreadsheet software will alsowork in the invention.

At the end of the matching, a value of the stress plateau and anescalation representative of the field data are produced. FIG. 5Adisplays an exemplary plot of ISIP data collected from the 6H well inthe Shale I formation along with the curve for the matched data and theoptimized stress plateau and escalation.

The benefit of using a spreadsheet with a least-squares based solver isthe ability to automatically calculate the quality of the match. FIG. 5Bdisplays a screenshot of the spreadsheet template for 6H. On the rightside of the screen, a Match Quality box displays the total error,variance, and relative variance for the least-squares optimization.These indicators indicate how much the matched data deviates from theobtained ISIP data in average for each stage, respectively in absolutepsis, or relative to the amount of stress escalation and are used toquantify the quality of the match. The user can set the acceptableamount of relative variance. However, a relative variance of 20% or lessis typically a good sign that the results of the analysis may betrusted. On the other hand, results should be ignored if the relativevariance exceeds 40-50%.

Once a match of the data is determined and has an acceptable relativevariance, the causes of the stress plateau are reviewed to ensure thatthe plateau is naturally occurring. FIG. 3 displays the workflow forthis section of the ISIP analysis. The workflow requires the calculationof the stress load (σ_(load)) through the use of type-curves. Thetype-curves were built by matching the analytical model of a multi-stagemechanical stress interference with the stress-escalation EQU. 1.

Type-curves were built for the load-normalized stress plateauΔσ_(plateau)/σ_(load)), escalation number and interference ratio as afunction of height, spacing and number of perf clusters. Thesetype-curves are shown in FIG. 4A-E.

Using the calculated stress plateau and escalation number during thematching step, a user can then extrapolate the stage spacing distanceover the total fracture height (s_(f)/2h_(f) ratio). This s_(f)/2h_(f)ratio can then be used to extrapolate the interference ratio.

Each extrapolation can theoretically be performed manually; however,this is fairly time-consuming. As such, each individual curve in FIG.4A-D was matched with a power-law correlation and each curve in FIG. 4Ewas matched with a polynomial correlation. These resulting equations canbe programmed into an Excel spreadsheet for quick calculations. For theload-normalized stress plateau, and escalation number, no singlecorrelation matched the type-curves over the entire sf/2hf interval.Thus, they were split into two correlations for sf/2hf<0.5 and >0.5. Forthe interference ratio, only one quadratic equation is sufficient tomatch the type-curves over the entire sf/2hf interval. Tables 1-3provides a listing of each type-curve equation for type curves builtunder the assumption that the hydraulic fractures are semi-infinite.

TABLE 1 Correlation Equations for Δσ_(plateau)/σ_(load) type-curvesPerforation Correlation Equation Correlation Equation cluster/Stage (0.1< s_(f)/2h_(f) < 0.5) (0.5 < s_(f)/2h_(f) < 1.5) 1 y = 0.4021x^(−2.147)y = 0.2717x^(−2.66) 2 y = 0.8769x^(−1.968) y = 0.5801x^(−2.523) 3 y =1.1601x^(−1.827) y = 0.7564x^(−2.528) 4 y = 1.3353x^(−1.814) y =0.7358x^(−2.627) 5 y = 1.4379x^(−1.74) y = 0.9288x^(−2.521)

TABLE 2 Correlation Equations for Escalation type-curves PerforationCorrelation Equation Correlation Equation cluster/Stage (0.1 <s_(f)/2h_(f) < 0.5) (0.5 < s_(f)/2h_(f) < 1.5) 1 y = 0.3555x^(−2.53) y =0.8325x^(−1.327) 2 y = 0.6786x^(−2.445) y = 1.3566x^(−1.448) 3 y =0.8908x^(−2.442) y = 1.6463x^(−1.381) 4 y = 0.8219x^(−2.573) y =1.8327x^(−1.443) 5 y = 1.0724x^(−2.444) y = 1.928x^(−1.36)

TABLE 3 Correlation Equations for Interference Ratio type-curvesPerforation cluster/Stage Correlation Equation (0.1 < s_(f)/2h_(f) <1.5) 1 y = 0.1442x² − 0.754x + 1.226 2 y = 0.0147x² − 0.4094x + 1.0698 3y = −0.0013x² − 0.3222x + 1.051 4 y = 0.0012x² − 0.304x + 1.0529 5 y =0.0093x² − 0.3059x + 1.0591

Through the use of the type-curves and/or their correlation equations,the user will be able to calculate the interference ratio. Theinterference ratio is relative magnitude of stress interference betweensubsequent stages, which is always between 0 and 1. The tighter thestage spacing, the larger the induced stress plateau is for a givenvalue of the escalation number. The interference ratio can then be usedto calculate the stress load (σ_(load)) using Equation 9.

$\begin{matrix}{\sigma_{load} = \frac{\Delta\;\sigma_{plateau}}{{Interference}\mspace{14mu}{Ratio} \times {Escalation}}} & {{Eq}.\mspace{11mu} 9}\end{matrix}$

If the stress plateau is naturally occurring, the stress load will havea value that is much smaller than the net pressure at shut-in(p_(net)=ISIP1−σ_(hmin)). On the other hand, when maximum horizontalstress is overcome, and stress escalation is basically cut short, thiswill cause the stress load to take abnormally high values. This meansthat the calculated fracture height is unlikely to be accurate. However,if the stress load is less than half the net pressure at shut-in,fracture reorientation is limited and the height calculation can betrusted.

Using type-curves, such as those in FIG. 4A-E or their equivalentcorrelation equations, the number of perforation clusters/stage, andstage spacing, the fracture height can be calculated. Calculatinghydraulic fracture height is fairly trivial in the cases where thestress plateau is naturally occurring, but becomes trickier ifhorizontal-stress anisotropy is overcome during fracturing. In thatcase, the escalation of stresses is being halted, causing the escalationnumber to decrease substantially. This in turn will result in a widelyunderestimated value of the hydraulic fracture height.

There are two strategies for situations where fracture reorientationtakes place. In the first strategy, the first couple of data pointsbefore the ISIP falls off are matched during step 2. In most casesthough, this strategy may not yield a favorable match when using fielddata, as the noise creates non-uniqueness when matching only a couplepoints.

The second strategy consists of assuming a value for the stress load andmatching the early escalation behavior with EQU. 1, for a fixed value ofthe stress load.

For most applications, ISIP analysis may be limited to calculatingin-situ horizontal stress anisotropy and hydraulic fracture height, asthese parameters are most needed for modeling. An advanced method of theISIP analysis was also constructed to be able to evaluate the hydraulicfracture length and induced fracture area. For this version, the numberof input parameters needed is increased. In addition to cluster spacing,number of perforation clusters/stage, well depth and frack closuregradient, you will also be required to provide an estimate for theYoung's modulus and Poisson's ratio, as well as the slurry volume pumpedfor each stage.

Equ. 10 is used to calculate hydraulic fracture length, and Equ. 11 isneeded for induced fracture area.

$\begin{matrix}{L_{f} = \frac{3V_{slurry}E}{\begin{matrix}{8{\pi\left( {1 - v^{2}} \right)}{h_{f}^{2}\left( {{{ISIP}(1)} - \sigma_{hmin}} \right)}} \\\left\{ {1 + {\left( {n_{cluster} - 1} \right)\left\lbrack {1 + \left( \frac{h_{f}}{2s_{cluster}} \right)^{2}} \right\rbrack}^{{- 3}/2}} \right\}\end{matrix}}} & {{EQU}.\mspace{11mu} 10} \\{A_{f} \approx \frac{3^{0.375}V_{slurry}n_{cluster}E}{\begin{matrix}{2\left( {1 - v^{2}} \right){h_{f}\left( {{{ISIP}(1)} - \sigma_{hmin}} \right)}} \\\left\{ {1 + {\left( {n_{cluster} - 1} \right)\left\lbrack {1 + \left( \frac{h_{f}}{2s_{cluster}} \right)^{2}} \right\rbrack}^{{- 3}/2}} \right\}\end{matrix}}} & {{EQU}.\mspace{11mu} 11}\end{matrix}$

Once the hydraulic fracture height and horizontal stress anisotropy arecalculated, the values can be used to optimize fracturing models andoperations. The results from the ISIP analysis can be inputted into anyknown reservoir simulation software that is commercially available ordeveloped in-house.

In some embodiments, the results are used in a reservoir simulationprogram to predict reservoir performance characteristics, such asfracturing, production rates, total production levels, rock failures,faults, wellbore failure, optimal stage and perforation cluster spacing,and the like. Or, the results are used to optimize and implement ahydraulic fracturing program or modify a hydraulic fracturing program orpattern for subsequent steps in a given well or wellpad. The ultimategoal is to use the results for executing a fracking program forsubsequent production of hydrocarbons via the now optimally frackedwell.

The present methods are exemplified with respect to the examples below.However, this is exemplary only, and the methods can be broadly appliedto any well undergoing fracturing or analytical models of intendedmulti-stage fracturing plans. The following examples are intended to beillustrative only, and not unduly limit the scope of the appendedclaims.

Test 1: Shale I Formation

Instantaneous shut-in pressure was collected for three wells in theShale I formation for analysis by the described methods. Two of thewells, 8H and 9H, have closely spaced perforation clusters of 17 feet,which is expected to induce a higher stress interference. The thirdwell, 1H, has a larger spacing of perforation clusters (35 feet).

The ISIP data was matched with EQU. 1 and the analysis followed theworkflow shown in FIG. 3. The ISIP evolution and match for all threewells is shown in FIG. 6 and the results for the analysis is shown belowin Table 4:

TABLE 4 ISIP analysis results from Shale I formation wells CalculatedCalculated stress s_(f) Δσ_(plateau) Interference σ_(load) hydraulicheight anisotropy Well (ft) (psi) Escalation s_(f)/2h_(f) Ratio (psi)(ft) (psi) Shale I Well 8H 85 1440 0.92 1.72 0.56 2795 >49 ~1440 Shale IWell 9H 85 1344 1.63 1.13 0.72 1227 >102 ~1344 Shale I Well 1H 140 11086.0 0.49 0.91 264 292 >1108

The stress anisotropy has been overcome for 8H and 9H, as the calculatedstress load is higher than the net pressure at shut-in (p_(net)=1080psi). The lower values of Interference Ratio compared to 1H, even thoughstage spacing has been reduced by 50%, are another indication. Thecalculated hydraulic heights for 8H and 9H will be meaningless becausethe stress load is higher than the net pressure at shut-in. However, thein-situ horizontal-stress anisotropy may be extracted from this data andused to optimize the fracturing design.

The third well, 1H, does not overcome horizontal stress anisotropy asevidenced by the calculated stress load being well below the netpressure at shut-in. This is a strong indication that horizontal-stressanisotropy is higher than 1108 psi. As such, the fracture was able toclose during the time separating the subsequent fracture stages. Thus,the height estimated by the ISIP analysis will correspond to the proppedheight of the fracture.

This study demonstrates that analyzing ISIPs for multiple wells in asimilar area can narrow down tremendously the range of horizontal-stressanisotropy. The analysis of ISIPs may shed light on the amount of stressneeded to overcome the in-situ stress anisotropy and thus favor thepropagation of complex fracture networks, especially in very lowpermeability matrix rocks.

For the Shale I formation, the hydraulic fracture height was calculatedfor a multiplicity of completion designs, and a total of 7 wells. Theresults are shown in Table 5.

TABLE 5 Calculated values of hydraulic height for 7 Shale I formationwells Calculated hydraulic Well S_(cluster) (ft) #clusters Fluid typeheight (ft) Shale I, Well 1H 35 4 X-linked gel 292 Shale I, Well 2H 35 5Slickwater 242 Shale I, Well 3H 35 5 Slickwater 235 Shale I, Well 4H 354 X-linked gel 192 Shale I, Well 5H 35 4 Slickwater 231 Shale I, Well 6H35 5 Slickwater 242 Shale I, Well 7H 35 5 Slickwater 298

The average value of the calculated hydraulic height for the 7 wellsanalyzed above is 248 feet, with a standard deviation of 33 feet.Applying ISIP analysis on a just few wells has provided confidence thathydraulic fractures propagate vertically most likely between 215 feetand 281 feet for all of these wells.

The estimates of the vertical propagation of the hydraulic fractures canthen be used in reservoir simulators for production forecasting andreservoir evaluation. Further, additional changes to the fracturingfluid and/or cluster number/spacing can be made to improve the designand implementation of the recovery plans, resulting in improvedrecoveries as compared with existing methods.

Test 2: Shale II Formation

Values of pressures taken up to 10 minutes after shut-in were analyzedusing the disclosed method to determine if they were suitable forevaluation by the ISIP analysis.

Pressure data was obtained from the well 1H in the Shale II formation,with large potential reserves. Thus, improved fracturing monitoringwould increase the recovery of the shale oil and be of great benefit.Shale II, well 1H has a perforation cluster spacing of 48 feet, a stagespacing was 192 feet and the perforation clusters/stage is 4.

FIG. 7 displays the pressure curves for the instantaneous, 3-min, and5-min shut-in pressure. As expected the pressure in the induced-fracturesystem drops quite rapidly in the first few minutes following shut-in,as the fluid in the fractures slowly leaks off in the formation and thefractures gradually close. The shut-in pressure curves thus shift downas more time elapses between shut-in and when the pressure is beingrecorded.

Each pressure curve was analyzed using the current methods. FIG. 8displays the ‘match’ curve using EQU. 1 and Table 6 display thecalculated parameters.

TABLE 6 Calculated hydraulic heights for instantaneous, 3-min, and 5-minshut-in pressures for Shale II, Well 1H Time after Calculated hydraulicshut-in Δσ_(plateau) (psi) Escalation height (ft) 0 701 1.38 154 3 min612 2.78 263 5 min 583 4.0 325

What is demonstrated clearly from this exercise is that fracking fluidleak-off is highly stress-dependent. Leak-off accelerates with each newfrack stage as stress interference builds up and the normal stressexerted on the fractures increases. As a result, the stress load in thelatter stages will be less than the stage load at earlier stages, whenlooking at non-instantaneous shut-in pressures, which violates afundamental assumption of the ISIP analytical model. For this reason,analyses of non-instantaneous shut-in pressure data will result inerroneous evaluations of the total stress induced by the completion andthe hydraulic fracture height.

Test 3: Outliers

There are many reasons why collected ISIPs may deviate from the trendcharacteristic of the stress-escalation equation. Some of the factorsmay be operational in nature; others may be related to the geology:

-   -   Stage screen-outs    -   Inconsistent slurry volumes or fluid type    -   Inconsistent lag time between stages    -   Well trajectory    -   Vertical/lateral heterogeneity in mechanical properties    -   Fault

In the event of a screen-out or equipment failure during a frack stage,it should be fairly straightforward to identify the ISIP datapoint andexclude it from the match. Because outlier ISIP values may impact thequality of the match, it is better to take them out of the analysiswhere possible. Typically, the completion engineer is most knowledgeableabout operational factors and may be able to identify the ISIP outliersmuch easier than others. Therefore, they are likely the best user to berunning the ISIP analysis portion of the method.

FIG. 9 shows an example of removing an outlier in the Shale IIIformation. The evolution of ISIP in the first two stages of Shale III,well 1 is clearly inconsistent with a typical stress-escalationbehavior. Now the difficulty is to determine which point(s) may beproblematic. This was achieved by comparing to another well in a similarformation and location (Shale III, well 2).

Comparing the two wells, it becomes clear the ISIP of stage 1 for ShaleIII, well 1 is too high, and the stage 2 ISIP may also be a bit low.Looking into the completion operations into more detail, it was foundthat just a couple hours prior to the first stage, a toe DFIT wasconducted on the same well. This explains the abnormally high value ofISIP for the first stage, as extra pressure and stress was present inthe near-wellbore region following the DFIT. As a result, to completethe analysis of Shale III, well 1, stage 1 ISIP was decreased to thesame gradient value as Shale III, well 2.

Variations due to heel/toe discrepancies can also present as outliers.ISIP variations occurring in the heel stages may generally be excludedfrom the analysis as they can only be explained bygeological/operational factors. Three different matches were conductedon the Shale IV, well 1 including:

-   -   1. All ISIP data points    -   2. Only the 12 first stages at the toe of the well (to exclude        variations in the heal section due to geological factors)    -   3. Same toe stages at the exception of stage 6, which exhibits        an abnormally high ISIP value, possibly caused by a nearby fault

As shown in Table 7, the consequences of the points to be included inthe match on the results of the ISIP analysis are relatively minor.Nevertheless, the third match including only the 12 toe-most stages, atthe exception of stage 6, would be the recommended choice, since thestress escalation mostly occurs during the first stages before reachinga plateau.

TABLE 7 Result of ISIP match for different value sets of Shale IV, well1 Match Δσ_(plateau) (psi) Escalation All points 753 0.77 12 toe stages779 0.85 12 toe stages w/o outlier 731 0.73

A similar process should be conducted in most ISIP analyses to excludepoints that may not be relevant, and check for the stability of the ISIPmatches for different sets of ISIP stage values.

To help with outliers, the match quality variance and relative variancefrom the least squares analysis can be used to evaluate the match. Theseindicators indicate how much the match deviate from the ISIP data inaverage for each stage, respectively in absolute psi's, or relative tothe amount of stress escalation. A relative variance of 20% or less is agood sign that the results of the analysis may be trusted. On the otherhand, results should be ignored if the relative variance exceeds 40-50%.

Test 4: Optimizing Fracture Spacing in Multi-Stage Completions

The analysis of ISIPs may also guide the process of decreasing stage andperforation cluster spacing and shed light on the amount of stressneeded to overcome the in-situ horizontal stress anisotropy and thusfavor the propagation of complex fracture networks, especially in verylow permeability matrix rocks. In naturally-fractured formations,spacing the perforation clusters so that a near-isotropic condition isreached may considerably increase the surface area stimulated, henceimproving the well productivity. The completion design needed to achievesuch goal will depend on the magnitude of in-situ horizontal stressanisotropy, hydraulic fracture height, the spacing between perforationclusters and the number of perforation clusters per stage.

In other formations that experience a strike-slip stress regime, meaningthat the overburden stress is the intermediate principal stress(σ_(hmin)<σ_(v)<σ_(hmax)), stress escalation may lead to the formationof horizontal fractures. Contrary to a normal-faulting regime wherereaching the intermediate stress tends to improve well productivity, atendency for horizontal propagation may severely contain height growth,the vertical effectiveness of the stimulation treatment, limit proppantconcentration, or worse cause screen-outs. In this context, the goalwill be to design the completion to avoid “bumping” into theintermediate stress.

Starting from the results of ISIP analysis the well from FIG. 6, we canstart to evaluate how changing the fracture spacing would impact thestress induced by the completion. Now that we know the hydraulicfracture height (2h_(f)=242feet), it is possible to calculate the stresscorrection factor Φ for various combinations of perforation clusterspacing and number of perforation cluster spacing/stage using EQU. 6.For instance, in a 25-feet cluster spacing and 5 perforationclusters/stage scenario, the correction factor would be equal to 0.992,0.944, 0.854, 0.741, and 0.629 for each of the perforation cluster, foran average stage value of 0.832.

Assuming an unchanged stress load (σ_(load)=320 psi) and using EQU. 4,the total stress induced by the completion would be equal to 1585 psi.The same process was repeated for many different perforation cluster andstage spacing combinations and the results are shown in FIG. 10. Theinitial configuration of well A is indicated by the grey point. Weassume a hypothetical scenario where the stress induced by thecompletion should stay below 2000 psi to not overcome the overburdenstress. With 3 perforation clusters/stage, the perforation clusterspacing would have to be 35 feet or higher. With 4 perforationclusters/stage, cluster spacing could be reduced down to 27 feet, and to22 feet and 19 feet respectively for 5 and 6 perforation clusters.

The following references are incorporated by reference in theirentirety.

US20120324462 Virtual flow pipelining processing architecture

U.S. Pat. No. 10,753,181 Methods for shut-in pressure escalationanalysis

1. A method for fracturing a reservoir, comprising: a. obtaining aninstantaneous shut-in pressure (ISIP) in a well in a reservoir aftereach of n stages of a diagnostic fracture injection test (DFIT), saidDFIT comprising injecting a volume of fluid at a low rate throughperforations in a cemented casing to create a small-scale hydraulicfracture, thereby obtaining ISIP data for each of said n stages of saidDFIT; b. inputting said ISIP data into a spreadsheet software stored ina non-transitory memory of a computer; c. comparing said ISIP data foreach of said n stages with a two-parameter exponential recovery equationagainst type-curves to estimate hydraulic-fracture height andhorizontal-stress anisotropy; d. inputting said estimatedhorizontal-stress anisotropy and said fracture height into a reservoirmodel software; e. optimizing a reservoir fracturing plan using saidreservoir model software to obtain an optimized reservoir fracturingplan; f. implementing said optimized reservoir fracturing plan tofracture said well in said reservoir; and, g. producing oil from saidwell.
 2. The method of claim 1, wherein ISIP is a pressure value past anearly rapid falloff as determined by extrapolating a slope at an end ofa pressure pulse caused by shut-in.
 3. The method of claim 1, wherein instep c) fracture height, fracture length, and fracture area are alsoestimated.
 4. The method of claim 1, wherein said type-curves includeload normalized stress plateau type curves, escalation type curves, andinterference ratio type curves.
 5. The method of claim

, wherein said shut-in pressure is measured at the surface, downhole, orboth.
 6. The method of claim 1, wherein if a stress load is less thanhalf a net-pressure at shut-in, fracture reorientation is limited, andsaid method may proceed, but if not, said method is discontinued.
 7. Themethod of claim

, wherein said optimized fracturing plan uses one or more modifiedparameter(s) selected from the group consisting of: cluster number perstage, cluster spacing, stage spacing, fracturing pressure, fracturingfluid type, fracturing fluid volume, fracturing fluid viscosity,proppant type, proppant mass, proppant concentration, pumping rate,pumping schedule or combinations thereof
 8. The method of claim 2,wherein in step c) fracture height, fracture length, and fracture areaare also estimated.
 9. The method of claim 2, wherein said type-curvesinclude load normalized stress plateau type curves, escalation typecurves, and interference ratio type curves.
 10. The method of claim 2,wherein said shut-in pressure is measured at the surface, downhole, orboth.
 11. The method of claim 2, wherein if a stress load is less thanhalf a net-pressure at shut-in, fracture reorientation is limited, andsaid method may proceed, but if not, said method is discontinued. 12.The method of claim 2, wherein said optimized fracturing plan uses oneor more modified parameter(s) selected from the group consisting of:cluster number per stage, cluster spacing, stage spacing, fracturingpressure, fracturing fluid type, fracturing fluid volume, fracturingfluid viscosity, proppant type, proppant mass, proppant concentration,pumping rate, pumping schedule or combinations thereof.
 13. The methodof claim 8, wherein said type-curves include load normalized stressplateau type curves, escalation type curves, and interference ratio typecurves.
 14. The method of claim 8, wherein said shut-in pressure ismeasured at the surface, downhole, or both.
 15. The method of claim 8,wherein if a stress load is less than half a net-pressure at shut-in,fracture reorientation is limited, and said method may proceed, but ifnot, said method is discontinued.
 16. The method of claim 8, whereinsaid optimized fracturing plan uses one or more modified parameter(s)selected from the group consisting of: cluster number per stage, clusterspacing, stage spacing, fracturing pressure, fracturing fluid type,fracturing fluid volume, fracturing fluid viscosity, proppant type,proppant mass, proppant concentration, pumping rate, pumping schedule orcombinations thereof.
 17. A method for fracturing a reservoir,comprising: a. obtaining an instantaneous shut-in pressure (ISIP) in awell in a reservoir after each of n stages of a diagnostic fractureinjection test (DFIT), wherein said ISIP is a pressure value past anearly rapid falloff as determined by extrapolating a slope at an end ofa pressure pulse caused by shut-in, and wherein said DFIT comprisesinjecting a volume of fluid at a low rate through perforations in acemented casing to create a small-scale hydraulic fracture, therebyobtaining ISIP data for each of said n stages of said DFIT; b. inputtingsaid ISIP data into a spreadsheet software stored in a non-transitorymemory of a computer; c. comparing said ISIP data for each of said nstages with a two-parameter exponential recovery equation againsttype-curves to estimate fracture height, fracture length, fracture area,and horizontal-stress anisotropy; d. inputting said estimated fractureheight, fracture length, fracture area, and horizontal-stress anisotropyinto a reservoir model software; e. optimizing a reservoir fracturingplan using said reservoir model software to obtain an optimizedreservoir fracturing plan; f. implementing said optimized reservoirfracturing plan to fracture said well in said reservoir; and, g.producing oil from said well.
 18. The method of claim 17, wherein saidtype-curves include load normalized stress plateau type curves,escalation type curves, and interference ratio type curves.
 19. Themethod of claim 17, wherein said shut-in pressure is measured at thesurface, downhole, or both.
 20. The method of claim 17, wherein if astress load is less than half a net-pressure at shut-in, fracturereorientation is limited, and said method may proceed, but if not, saidmethod is discontinued.
 21. The method of claim 17, wherein saidoptimized fracturing plan uses one or more modified parameter(s)selected from the group consisting of: cluster number per stage, clusterspacing, stage spacing, fracturing pressure, fracturing fluid type,fracturing fluid volume, fracturing fluid viscosity, proppant type,proppant mass, proppant concentration, pumping rate, pumping schedule orcombinations thereof.